Borehole equipment position detection system

ABSTRACT

It is important to know the precise position of equipment when testing of the BOP, testing the wellhead, flow testing the well, kick control, well circulation and testing of spool trees between the wellhead and the BOP. Accordingly, there is provided a system for determining the real time position of equipment within a bore, the system including a data input means for inputting data concerning the physical characteristics of components which are run into the bore; a sensing means located, in use, within the bore and including a sensor for determining data concerning at least one physical characteristic of the equipment at a given time; a data storage means for recording the inputted data and the determined data; and a comparison means for comparing the input data and the determined data to establish which part of the equipment is being sensed by the sensor.

FIELD OF THE INVENTION

This invention relates to a system for determining the position ofmoving equipment within a bore such that, for example, an operator of adrilling system can determine the diameter, shape or orientation of thevertically moving equipment at specific locations within a well,especially at the wellhead and at the blow out preventer (BOP).

BACKGROUND TO THE INVENTION

When drilling in subsea applications, which can be at a water depth ofas much as 10,000 feet (3,000 metres), it is important to know thelocation of the equipment with respect to the BOP, the wellhead, in thecased hole and in the bore of the drilled well. For example, it isimportant to know how equipment needs to be positioned in and along thebore for operations to be performed correctly.

The prime operations are: drilling the well, casing and cementing, welltesting, completion and running any equipment inside the completion, awell workover and well intervention. In addition to the well operations,there are the system tests to check the integrity of individual systemsand that they are performed as required. These may include the well,wellhead and BOP pressure tests and the BOP operating tests. A subseawell also creates additional complications in respect to a well kickoperation or underbalance drilling (i.e. snubbing in or out of the hole)and the requirement to carry out an emergency disconnect and later thereestablishment of the well.

While carrying out all these operations from a floating vessel, it isimportant to know accurately, at any instant, the position of items ofequipment within the system.

When drilling a subsea well, the prime pressure containing equipmentthat contains possible formation pressures includes the subsea wellhead,the casing which is hung from and cemented to the wellhead and the BOPon the wellhead.

A BOP assembly is a multi closure safety device which is connected tothe top of a drilled, and often partially cased, hole. The accessibletop end of the casing is terminated using a casing spool or wellheadhousing to which the BOP assembly is connected and sealed.

The wellhead and BOP stack (the section in which rams are provided) mustbe able to contain fluids at a pressure rating in excess of anyformation pressures that are anticipated when drilling or when having topump into the well to suppress or circulate an uncontrolled pressurizedinflux of formation fluid. This influx of formation fluid is known as a“kick” and reestablishing control of the well by pumping to suppress theinflux or to circulate the influx out under pressure is known as“killing the well”. An uncontrolled escape of fluid, whether liquid orgas, to the environment is termed a ‘blow out’. A blow out can result inmajor leak to the environment which can ignite or explode, jeopardizingpersonnel and equipment in the vicinity, and pollution.

Although normal drilling practices provide a liquid hydrostatic pressurebarrier to a kick, a final second safety barrier is providedmechanically by the BOP assembly. The BOP assembly must close and sealon tubular equipment (i.e., pipe, casing or tubing) hung or operatedthrough the BOP assembly and ultimately must be capable of shearing andsealing off the well. A general term for a tubular system run into thewell is called a string. Wells are typically drilled using a tapereddrill string having successively larger diameter of tubulars at thelower end. When running a completion or carrying out a workover, variousdiameter of tubulars, coiled tubing, cable and wireline and anassortment of tools are run. In addition, dual tubulars, or tubularswith pipes and cables as a bundle, must be considered.

A subsea conventional BOP assembly is attached to a wellhead and isprovided with a number of rams either to seal around different settubular diameters or to shear and seal the bore. These rams should berated to perform at pressures in excess of any anticipated wellpressures or kick control injection pressures which are approximately 10to 15 kpsi (69-103 MPa). A minimum of one annular is provided above therams to cater for any tubular diameter or for stripping in or out underpressure. An annular is a hydraulically energized elastometric toroidalunit that closes and seal on varying diameters of tubular member whetherstationary or moving into or out of the well. Due to the nature of thispressure barrier element, a lower maximum rated working pressure ofabout 5 kpsi (34 MPa) is normally available.

Above the annulars, there are no further well pressure barrier elementswith the riser only providing a hydrostatic head, liquid containment andguidance of equipment on a normal pressure controlled drillingoperation. For a subsea riser system, the hydrostatic head of thedifferent drilling liquids over the ambient sea water pressure means thelow pressure zone above the subsea BOP assembly must still withstandhydrostatic pressures of, depending upon the depth of water,approximately 5 kpsi (34 MPa).

The conventional BOP assembly in effect provides a three zone pressurecontainment safety system. The three zones typically consists of thefirst high pressure lowermost section encompassing the rams, the mediumpressure second zone having the annular or annulars and the low pressurethird zone being the bore open to atmosphere and, on a subsea system,the riser bore to the surface vessel. Therefore it is critical that thecorrect rams are closed on the correct diameter and full pressureintegrity is achieved. In an emergency disconnect it is important that,besides sealing on the pipe or tubular, the pipe is held and not droppeddown the hole.

A BOP can be fitted with a ram or rams to suit various diameters ofdrill pipe, tubing or casing. Variable rams can be used, havingcarefully selected their range. A BOP is fitted with the rams mostlylikely to be needed in a certain drilling/workover phase. If a stage isreached where an inadequate range of rams are in the BOP to handle thetools/equipment to be used in the next sequence, the BOP has to bepulled and appropriately redressed.

When drilling or carrying out well intervention on a subsea well wherethe wellhead is at the seabed, the subsea BOP attached to the subseawellhead is connected to a buoyant floating drilling vessel by a riser.A floating drilling vessel should maintain its station vertically abovethe well to enable well operations to be performed.

Failure to do so caused by weather conditions, current forces, equipmentmalfunctions, drift off or drive off, fire or explosion, collision ofother marine incidents means it is necessary if possible to make thewell safe, isolate the well at the seabed and disconnect the risersystem. In a severe emergency, shearing any tubulars or equipment in theBOP bore, sealing the well to full working pressure and disconnectingthe riser system is required to be achieved in under 30 seconds.

At present, in order to know what components are run through the drillfloor, a manual record of the relevant dimensions, such as the lengthand the diameter of components are logged. These records are typicallymade in a notebook before being totalled up. Mathematical errors canoccur easily during the totaling or components can be left out of thetally entirely or additional equipment, over and above that scheduled tobe run, run in through the rotary table can be ignored or forgotten.Therefore, on a number of occasions, the accuracy of the tally isquestionable.

Furthermore, as there are a wide variety of components which can be runin the hole, often with minor variations in length for what otherwiseappear to be identical components, it is important that each componentis measured individually before it is attached to the string. It is easyfor minor errors in measurement of each component to add up to asignificant error over the length of the string.

A further problem is that even when the measurements are accuratelytaken at the rig, these measurements are passive, i.e. on unstresseddimensions of the component. Once the component has been run in on astring, it may have 5,000 metres of additional components hanging fromits end and, although this would not produce a significant change inlength of a single component, when the total change is added-up over allcomponents of the drill string, the change can be significant.

Furthermore, as the riser extending between the wellhead and the drillrig may be 2000-3000 m in length, it is subject to subsea currents andmay be caused to “snake” between the rig and the wellhead. In this case,the length of drill string run into the riser is not directly comparableto the straight distance between the rig and the wellhead.

Additional problems are encountered as the drilling rig heaves on thesea surface such that its position, which is dependent on the tide andthe vessel draft, is constantly changing with respect to the sea bed.This can, in part, be compensated for by the use of telescopic jointsand a travelling block, but these additional factors need also to beincluded in any calculation of the position of the string. As the rigcan heave in a matter of seconds, it can, in rough conditions, beimpossible to determine accurately the position of the string given thatthe calculations required at present are cumbersome and complex.

It is critical at certain instances to know the position of equipment inthe hole and, on a floating vessel, this requires knowledge of thetally, water depth, the draft and any change of draft of the vessel,swell or tidal heave, position of the travelling block, the stroke ofthe compensator and the depth of hole drilled since the last summationwas made. This does not take into account snaking of the riser due tocurrents or cross currents in deep water, or the extension of thetubular string due to tension and weight. It is therefore difficult todetermine accurately what component is at any given depth in a quick andaccurate manner.

An example outlining a subsea well operation is an emergency disconnectinvolving the drilling string.

The accurate position of the drill string is required in the event of anemergency shut in of the BOP by closure of, for example, the shear blindrams in the BOP stack. The shear blind rams are those which can cut thedrill string or a pipe or tubing and then seal the BOP bore when thereis a need to carry out an emergency disconnect of the riser system fromthe BOP stack. The shear blind rams are activated with only a set forceand therefore, should the rams close on a section of equipment which issignificantly larger than the shear capability of the rams, for exampleon a joint between adjacent pipe sections, the rams may not fully severthe drill string thereby not closing sufficiently to seal the well andallow an emergency disconnect to be carried out correctly. To preventthe drill string falling down the hole, and to enable the drill stringto be available to kill and circulate the well on reconnection, it isvery advisable to be able to hang the drill string off on a set of piperams. This is achieved by resting an up-set diameter of the string on aset of pipe rams below the blind shear rams.

For operations of this sort, it is necessary to know the position of aspecific part of the drill string to approximately one metre overanything up to 3,000 metres:

Further examples in which it is important to know the precise positionof equipment is in testing of the BOP, testing the wellhead, flowtesting the well, kick control, well circulation and testing of spooltrees between the wellhead and the BOP.

Accordingly, it is an aim of the present invention to provide a systemwhich enables the above problems to be overcome and allows the operatorof the drilling system to know the precise position of a string, whichmay be moving, relative to a section of the well, the BOP or thewellhead at any given moment.

SUMMARY OF THE INVENTION

According to the present invention, there is provided a system fordetermining the real time position of equipment within a bore, thesystem comprising:

a data input means for inputting data concerning the physicalcharacteristics of components which are run into the bore;

a sensing means located, in use, within the bore and including a sensorfor determining data concerning at least one physical characteristic ofthe equipment at a given time;

a data storage means for recording the inputted data and the determineddata; and

a comparison means for comparing the input data and the determined datato establish which part of the equipment is being sensed by the sensor.

Preferably, the information input to the data input means includes thelength, shape and/or diameter(s) of components making up the equipmentand run in or out of the bore. Many components may have multiple changesin diameter over their length and it is important that all suchinformation is entered into the data input means.

Thus, the present invention provides a system by which the exactsignature profile of the equipment is recorded as it is run into or outof the bore and a sensor, located at the relevant location in the bore,provides information relating to changes in a known physicalcharacteristic of the equipment. By comparing the sensed data and theknown data, it is possible to work out which part of the equipment isadjacent to the lower sensor and therefore the position of the equipmentrelative to the BOP and the wellhead.

Preferably, the information input to the data input means also includesthe distance between the changes in diameter, either along a singlecomponent or between diameters on adjacent components. Preferably, thesensor determines the shape and/or diameter of the equipment at a giventime.

The sensing means preferably includes a means for determining thedistance between successive changes in diameter.

Preferably, the system further comprises a sensing means for determiningthe direction of travel of the equipment in the bore and this may bepart of the downhole sensor or a vessel based sensor.

The system may be used on a subsea bore having a wellhead with a BOPconnected to it, which, in turn has a riser connected to it which, inturn, is connected to a drilling rig having a telescopic joint, aderrick, a travelling block/compensator and draw works.

Preferably, a further sensor is located, in use, in the upper portion ofthe riser fixed to the vessel to determine the profile of the equipmentas it is run into the riser system.

Furthermore, it is preferable that a travel sensor is located on thetelescopic joint to measure the movement of the telescopic joint betweenthe floating drilling vessel and the top end of the riser linked to theseabed or to compute the travel from a line travel sensor on a risertensioner line.

Another variable is movement in the derrick between the connection tothe equipment and the vessel caused by the compensator stroking andoperations of the draw works. A location sensor on the lower part of thecompensator relative to the derrick could be considered. A physicalmeans would be to monitor the stroking of the compensator with a travelsensor and to register the position of the travelling block in respectto the derrick. A method is to monitor line travel of the drill linefrom the draw works to the travelling block taking account of the numberof sheaved lines to obtain the true travel.

The data input means is preferably a further sensor of the type used inthe bore and it can therefore measure accurately the diameters and thelengths of all equipment run or pulled through the drilling vessel'sdrill floor. This information can be enhanced by referencing detailedproduct specifications which could include internal diameters, type ofconnection, strength and identification number. This would then providea cross reference between what is actually run and what was scheduled tobe run.

With an accurate knowledge of the equipment's signature profile andadditional information, the sensor in the bore actively monitors themotion of the equipment relative to the fixed position of the sensor andtherefore relative to the wellhead. By combining these two sources ofinformation with the well, wellhead, BOP configuration data, theposition of any item of equipment can be related to any point in thewell.

Using a microprocessor to collate this information/data, an activeanimated visual display may then be produced on a visual display device,such as a monitor, at a choice of scales most suited for the operationat the desired section of the well system.

This invention described in respect to a subsea drilling BOP can equallybe applied to workover BOPs, wireline or coil tubing BOPs. Equally thesystem can cater for wire, cable or coil tubing operations by recordingthe length of cabling run past a line travel sensor.

A surface sensor, that is one on the drilling rig, may be provided toregister the length of individually made up items of equipment. Thereason for this is that in certain circumstances, a section of theequipment run into the bore may be made up of a plurality of tubularswhich, when joined to each other, have a continuous outer diameter (ieexternal flush drill collars and liner pipes). The surface sensor canregister their lengths as the joints are made up although a stringsensor lower down the riser would not be able to detect any diameter orshape change.

Once the wellhead with the surface casing string, BOP and riser systemis run, all subsequent casing strings and the drilling strings used todrill the next section of hole can also be recorded. This will allow anaccurate elevation of casings within casings in the well at any depth tobe formulated as casing strings are run and cemented inside the previouscasing.

The ability of the bore sensors to monitor the shape and orientationmeans that when, carrying out certain down hole tasks, the number ofrotations of the equipment can be registered at the BOP sensor, ratherthan having to rely on knowledge of the number turns made at thesurface. The problem with relying solely on the information from thesurface is that there may be some relative twist on the equipment run,such that, for example, ten turns at the surface only corresponds tofive turns at the sensor.

By combining a knowledge of the time a string has been in its positionand how much it has been rotated, likely wear characteristics in theriser or in the cased hole can be predicted and may then be reduced.

The down hole sensor(s) is (are) preferably located in a retrievablepart of the LRP/riser system, such as the low pressure area of theBOP/riser, thereby allowing easier maintenance, service and repair.Additionally no disconnect and make-up interface is required comparedwith a BOP stack mounted sensor system.

BRIEF DESCRIPTION OF THE DRAWINGS

One example of the present invention will now be described withreference to the accompanying drawings, in which:

FIG. 1 is a schematic longitudinal cross sectional view through a subseawell being drilled by a floating vessel showing the well, wellhead,subsea BOP, riser and drilling rig incorporating the present invention;

FIG. 2 is a schematic longitudinal cross sectional view of the drillingrig top side of FIG. 1;

FIG. 3 is a schematic longitudinal cross sectional view of a typicalsubsea BOP of FIG. 1;

FIG. 4 is a schematic longitudinal cross section through the BOP of FIG.1 during normal drilling;

FIG. 5 is a schematic longitudinal cross section through the BOP of FIG.1 at the start of an emergency disconnect;

FIGS. 6 and 7 are schematic longitudinal cross sections through the BOPof FIG. 1 during the emergency disconnect;

FIG. 8 is a schematic longitudinal cross sectional view through the BOPof FIG. 1 after the emergency disconnect;

FIG. 9 is a schematic longitudinal cross sectional view through part ofthe BOP after an emergency disconnect showing the status of the rams andthe valves;

FIG. 10 is a vertical schematic cross section view through one exampleof a sensor which could be used as part of the present invention; and

FIG. 11 is a horizontal schematic cross-sectional view of the sensor ofFIG. 10.

DESCRIPTION OF PREFERRED EMBODIMENTS

A drilling rig 2, a subsea BOP assembly 10 and wellhead assembly 11 isshown schematically in FIGS. 1 to 3. A wellhead assembly 11 is formed atthe upper end of a bore into the seabed 12 and is provided with awellhead housing 13. The BOP assembly 10 is, in this example, comprisedof a BOP lower riser package (LRP) 15 and a BOP stack 16. The LRP 15 andthe BOP stack 16 are connected in such a way that there is a continuousbore 17 from the lower end of the BOP stack through to the upper end ofthe LRP. The lower end of the BOP stack 16 is connected to the upper endof the wellhead housing 13 and is sealed in place. The upper part of theLRP 15 consists of a flex joint 20 which is connected to a riser adaptor28, which is, in turn, connected to a riser pipe 19. The riser pipe 19connects the BOP assembly 10 to a surface rig 2.

Within the bore 17 and the riser pipe 19, a tubular string 21 isprovided. Such a string is comprised of a number of different types ofcomponent including simple piping, joint members, bore guidanceequipment, and may have attached at its lower end, a test tool, a drillbit or a simple device which allows the flow of desired fluids from thewell. The wellhead housing 13, as an example, is shown with one wearbushing 22 and a number of well casings 23 which have previously beenset in the wellhead and which extend into the hole in the sea bed 12.

The BOP stack is provided with a number of valve means for closing boththe bore 17 and/or on the string 21 and these include lower pipe rams30, middle pipe rams 31, upper pipe rams 32 and shear blind rams 33.These four sets of rams comprise the high pressure zone in the BOP stack16 and they can withstand the greatest pressure. The lower, middle andupper pipe rams are designed such that they can close around the string21. However, the rams are only designed to close around a specificdiameter of the drill string, for example on a 5 inch (125 mm) pipesection, and it is therefore important to know, in the event of, forexample, an emergency disconnect, whether or not the rams are opposite asuitable section of the drill string 21 to enable them to closecorrectly and provide a seal.

Of course, when the lower 30, middle 31 and upper 32 pipe rams areclosed, whilst the bore 17 is sealed, the bore of the drill string 21itself is still open. Thus, the shear blind rams 33 are designed suchthat, when operated, they can cut through the drill string 21 andprovide a single barrier between the upwardly pressurized drilling fluidand the surface.

Above the shear blind rams 33, a lower annular 34 and an upper annular35 are provided and these can also seal around the drill string 21 whenclosed and provide a medium pressure zone.

The lower pressure zone is located above the upper annular 35 andincludes the flex joint 20, the riser adaptor 28 and the riser 19. Thelow pressure containing means of this zone is merely the hydrostaticpressure of the fluid which is retained in the bore open to the surface.

Extending from the surface rig 2 to the BOP assembly 10 are choke 40 andkill 41 lines for the supply of fluid to or from the BOP. The choke line40 is, in this example, in fluid communication with the bore 17, in thisexample, three locations, each location having an individual branchwhich is controlled by a pair of valves (see FIG. 3). The uppermostvalves are inner 45 and outer 46 gas vents and the branch on which theyare located extends to the bore 17 below the upper annular 35. The chokeline 40 extends, passing in and out of gas vents, through a choke testvalve 47 and enters the bore 17 via upper, inner 48 and outer 49 chokevalves above the middle pipe rams 31 and via lower, inner 50 and outer51 choke valves below the lower pipe rams 30.

On the opposite side of the BOP stack, the kill line 41 is equipped witha kill test valve 52 before the kill line 41 enters the bore 17 at twolocations, again each of which is via a pair of valves; upper, inner 54and outer 55 kill valves and lower, inner 56 and outer 57 kill valvesrespectively. The upper branch is between the upper pipe rams 32 and theshear blind rams 33 and lower branch is between the lower 30 and middle31 pipe rams.

The drill rig 2 is connected to the riser 19 by means of a telescopicjoint 60 (see FIG. 2). In this example, the upper end 61 of thetelescopic joint 60 is spaced vertically from the lower surface of thedrill floor 62 of the drill rig 2 and, as such, extending from the lowersurface of the drill floor, there is provided a telescopic joint outerbarrel 64 which extends into, and in sealing engagement 61 with, thetelescopic joint outer barrel 64 of the telescopic joint 60. As thedrill floor moves vertically relative to the outer barrel 64 of thetelescopic joint 60, the inner barrel 63 can slide within a recessportion of the outer barrel 64. The telescopic joint 60 is suspendedfrom the drill floor 62 by means of riser tensioner cables 65 which areconnected, via sheaves 84, to motion compensating tensioners (notshown). The upper end of the inner barrel 63 is connected to a flexiblejoint 66 which, in turn, which forms the diverter assembly 67 extendingbelow the lower surface of the drill floor 62. The diverter assemblyannular 68 is provided to seal the bore 17 if necessary. Drilling mudwhich passes up the riser 19 is directed through a mud outlet 69 througha flow nipple 70. The choke and kill lines 40,41 are connected torespective flexible choke and flexible kill 71, 72 lines which extend onto the main deck 73 of the rig 2 and connect to the manifold and a highpressure pumping system.

On the upper surface of the drill floor 62, there is a derrick 74 whichsupports a set of sheaves 75 known as the crown block. The travellingblock 76 is connected to a compensator and possibly a top drive assembly77 which is, in turn, connected to the string 21. The crown block 75 andthe travelling block 76 are connected by a cable 79 which is connectedinto draw works 78.

A number of sensors are included in the BOP 10 and the drilling rig 2.These include a riser adaptor bore object sensor 80 which is located atthe upper end of the LRP 15 and a telescopic joint bore object sensor 81which is located at the upper end of inner barrel 63. Each of thesesensors can detect the diameter, shape and orientation of the string 21which is within the sensor and they can transmit the informationelectronically to a centralized data collection means and amicroprocessor (not shown). The sensors 80 and 81 thereby provide aseries of measurements which can be used in determining the location ofthe string 21 at any given time. In particular, the telescopic jointbore object sensor 81 provides a sequence of measurements, especiallythe diameters, changes in diameter, shape and orientation of the string21, as it is run into the riser 19 and provides reference data for latercomparison. The riser adapter bore object sensor 80 detects thediameters and changes in diameter the shape and orientation of thestring 21 as it passes the sensor 80 near the BOP 10. By comparing thesequence of diameters and diameter changes measured by the riser adaptorbore object sensor 80 with the reference data provided by the telescopicjoint bore object sensor 81, the processor on the rig can determinewhich section of the drill string which is within the BOP at any giventime.

The BOP 10 may also be provided with ram travel sensors 90 located oneach ram of the lower 30, middle 31, upper 32 pipe rams and on the shearblind rams 33. Additionally, annular travel sensors 91 can be providedon the lower 34 and upper 35 annulars. In particular, the sensors candetermine whether or not each of the rams or annulars has beenactivated, and if so, whether the ram or annular is in the correctposition for sealing around the string 21.

Further sensors can be provided to measure other movement, such as heaveof the rig, which would affect the location of the string relative tothe BOP.

For example, a heave sensor 86 is provided between the drill floor 62and the telescopic joint outer barrel 61 to account for variations dueto heave of the rig. Additionally a mechanical travel sensor is includedon the compensator/top drive assembly 77 to take account of the movementthe compensator. The position of the travelling block 76 is known by theuse of a line travel sensor 85 in the draw works 78.

An example description of the how the system can operate is shown inFIGS. 4 to 8. The example taken is an emergency disconnect of the vesselfrom the well between the BOP stack and the LRP.

FIG. 4 shows a cross sectional view through the BOP when a drill string21 is operating in a conventional drilling mode and is rotating. In thissituation, the riser adaptor bore object sensor 80 can detect changes indiameter of the tool joint 92, in this case, an increase in diameter,and this information would be relayed to the data storage means (notshown). In this example, the change in diameter at the tool joint 92 iseffected by a section in which the diameter changes gradually from thesmaller main pipe diameter to the larger diameter of the joint 92. Inthis case, both sides of the tool joint are provided with the sameprofile but, if different profiles were used on each side of the tooljoint 92, it would be possible to determine in which direction the drillstring 21 was moving as it passed the sensor 80 by detecting the shapeof the profile of the diameter change. Alternatively, an additionalsensor or an array of vertical sensors (not shown) could be provided tosense the direction and distance of travel of the string 21. The abilityto know the direction and distance of travel is of considerableimportance in determining the section of string which is adjacent to thesensor 80 and therefore what profile is currently in the BOP.

FIGS. 5 to 8 show how, after determining the location of the string 21within the BOP 10, and therefore whether or not any tool joints 92 arepresent, an emergency disconnect can then be safely carried out. In thisexample, the rotating drill string 21 is monitored by the sensor 80 andthe tool joint 92 is observed to be moving relative to the BOP. Thelocation and operating status of the rams and annulars can be confirmed,by using the sensors 90 and 91, to be in the fully retracted positions.

When a rapid controlled emergency disconnect is required, the drillstring 21 is picked up until the tool joint 92 is above the lower piperams 30 and rotation is stopped. The drill string 21 is held in thisposition and confirmation is obtained that the tool joint is above thoserams. The lower pipe rams 30 are then lightly closed and the sensors 90connected to the lower pipe rams 30 can confirm the correct closure ofthe rams on the drill string 21. The lower pipe rams 30 are closed onlyunder a low operating pressure at this stage.

Then the drill string 21 is lowered such that the tool joint 92 rests onthe upper surface of the lower pipe rams 31 which will now support thedrill string (FIG. 6). This can be detected by a loss of drill stringweight recorded at the surface. At this stage, full ram close pressureis then applied to the lower pipe rams 30. The sensors 90 can againconfirm that the rams are fully closed around the drill string 21. Ifpresent, ram locks (not shown) can be operated to prevent the lower piperams 30 from being forced apart.

A similar operation can then be carried out on the upper pipe rams ifthe diameter of drill string across the closure point of the upper piperams 32 is suitable (see FIG. 7).

Next, the shear blind rams 33 can be closed, cutting the string 21, withthe upper part being pulled up. Again this can be confirmed by the useof sensor 90. The ram locks, if present, can also then be activated.

The lower riser package 15 can then be disconnected from the BOP stack16 and pulled clear of the remaining subsea components (FIG. 8).

The current method is to take the drill string position from thedrillers tally and then account for heave, for vessel draft, for theposition of the travelling block, note if the rig is off center, andthen estimate the positions of the tool joints. Using the bore equipmentdetection system operating a drill floor monitor, and displaying avisual presentation, the driller can visually observe the situation atany given time.

FIG. 9 shows a typical exploded display that could be displayed on adrill floor monitor (not shown) and gives a view of the lower 30, middle31 and upper 32 pipe rams after an emergency disconnect has been carriedout. In this example, the lower 30 and middle 31 variable pipe rams havebeen closed on the smaller diameter of the main drill string 21 and theram lock would be in the closed position. Additionally, the shear blindrams 33 would also be closed and again the ram locks would be in theclosed position. However, the middle pipe rams 31 have not been operatedand therefore the ram locks would still be in the open position. Thisform of checking would be carried out at all stages within the emergencydisconnect procedure to ensure that each ram and annular was in theappropriate position for that stage of the operation.

FIGS. 10 and 11 shows a close up view of one of the bore object sensors80 or 81. The sensor is an electronic/magnetic sensor that can determineelectronically and accurately the diameter of a body within the bore 17and its location within the bore, i.e. if the tubular string or stringsis on one side of the bore, thereby indicating that the rig may not bevertically above the wellhead. A full string signature profile can beobtained by the surface bore object sensor 81 and this can be comparedwith the observed string profile which is determined by the riseradaptor bore object sensor 80.

As the drill string 21 is run down through each of the sensors 80, 81, aprofile is generated of the change in diameters and by comparing thedata from the surface bore object sensor 81 with the measured data fromthe riser adaptor bore object sensor 80, it is possible to determinewhich section of the drill string 21 is within the BOP. If necessary,additional bore object sensors could be located in other positionswithin the BOP or in the riser itself.

The bore object sensor is formed by using a non-metallic body 100,possibly formed from an epoxy, within which are mounted a set ofemitters 101 and receivers 102. The emitters and receivers are connectedto a microprocessor (not shown). Using an electrical pulse sent out bythe emitters 101, a uniform electric field would be monitored by thereceivers 102 if no object were present in the field of the sensor.However, when an object, such as the drill string, enters this field,the field flux lines 103 are disturbed and each receiver 102 can monitorthe change in the electric field. When requiring to sense non metallicobjects, the frequency will have to be varied. This allows themicroprocessor to compute the closeness and the shape of the object toeach of the receivers and therefore determine its size, shape,orientation and position within the bore.

1. A system for determining the real time position of components withina bore, the system comprising: a data sensor for obtaining dataconcerning the physical characteristics and profile of the components ata first location as the components run in the bore; a sensing apparatuslocated, in use, within the bore and including a bore sensor fordetermining data concerning at least one physical characteristic or theprofile of the components at a given time at a second location; datastorage for recording the obtained data and the determined data; and aprocessor for comparing the obtained data and the determined data toestablish which of the components or part thereof is being sensed by thebore sensor at the second location.
 2. A system according to claim 1,wherein the data sensor is arranged to accept information including thelength, shape and/or diameter(s) of the components run in or out of thebore.
 3. A system according to claim 1, wherein the data sensor isarranged to accept information including the distance between any changein diameter on a single component run in the bore.
 4. A system accordingto claim 1, wherein the bore sensor determines the diameter and/or shapeof the components at a given time.
 5. A system according to claim 1,wherein the sensing apparatus further comprises another sensor fordetermining the distance between successive changes in diameter oftubular components.
 6. A system according to claim 1, wherein thesensing apparatus includes a direction sensor for determining thedirection of travel of the components within the bore.
 7. A systemaccording to claim 6, wherein the sensing apparatus includes a secondbore sensor for determining the diameter of the components.
 8. A systemaccording to claim 1, further comprising a distance sensor fordetermining the distance travelled of equipment run in or out of thebore.
 9. A system according to claim 1, wherein the processor is amicroprocessor.
 10. A system according to claim 1, wherein the bore is asubsea bore and the system further comprises a wellhead, a blow outpreventer connected to the wellhead, a riser connecting the BOP with adrill rig, the drill rig including a travelling block/compensatorattached to a derrick, draw works and a telescopic joint connecting theriser to the drill rig.
 11. A system according to claim 10, furthercomprising a travel sensor on the telescopic joint for determining therelative movement between the riser and the drilling rig.
 12. A systemaccording to claim 10, further comprising a travel sensor fordetermining the relative movement of the top end of the riser and therig.
 13. A system according to claim 10, wherein the drill rig islocated on a vessel and the sensing apparatus further includes: a travelsensor on the telescopic joint to measure the movement between the rigand the riser; a location sensor on the compensator to measure themovement between the component and the vessel; a diameter sensor tomeasure the diameter of the component; a motion sensor to measure themotion of the component relative to the wellhead; and a surface sensorto measure the length of the components.
 14. A system according to claim10 wherein the data sensor is located adjacent the rig and the sensingapparatus is located adjacent the wellhead.
 15. A system according toclaim 1, further comprising a visual display for displaying boreinformation to a user.
 16. A system according to claim 1, wherein thebore sensor includes a plurality of emitters emitting flux lines and aplurality of receivers for receiving the flux lines.
 17. A system fordetermining the real time position of components within a bore, thesystem comprising: a sensor for obtaining data concerning the physicalcharacteristics and profile of the components which are run into thebore at a run-in location; a sensing means located, in use, within thebore and including a bore sensor for determining data concerning atleast one physical characteristic or the profile of the components at agiven time; a data storage means for recording the obtained data and thedetermined data; and a comparison means for comparing the obtained dataand the determined data to establish which part of the components isbeing sensed by the bore sensor; and wherein the bore is a subsea boreand the system further comprises a wellhead, a blow out preventerconnected to the wellhead, a riser connecting the BOP with a drill rig,the drill rig including a travelling block/compensator attached to aderrick, draw works and a telescopic joint connecting the riser to thedrill rig; and wherein the comparison means is arranged to determine theposition of the components relative to a fixed point on the seabed. 18.A system determining the real time position of components extendingthrough a telescopic joint and riser from a rig at a sea surface througha wellhead at the sea floor and into a well bore, the system comprising:a distance sensor to determine the distance of travel of the components;a travel sensor on the telescopic joint to measure relative movementbetween the rig and the riser; a first sensor adjacent the rig to obtaindata on the physical characteristics and profile of the components asthey are run into the riser; a second sensor adjacent the wellhead todetermine data on the physical characteristics and profile of thecomponents as they are run into the well bore; and a processor forcomparing data from the sensors to establish which of the components orpart thereof is being sensed by the second sensor, wherein a result ofthe comparison is displayed.
 19. The system of claim 18 wherein thefirst sensor measures the length and diameter of the components.
 20. Acomputer-readable medium containing software that, when executed by aprocessor, causes the processor to: obtain first data from a firstsensor at a first location sensing a component's characteristics; obtainsecond data from a second sensor at a second location sensing thecomponent's characteristics; compare the first data with the second datato establish the component characteristics at the second location; andstore a result of the comparison.